Process for producing distillate fuels from syngas

ABSTRACT

A process for producing distillate fuels, such as a diesel fuel, from a syngas feedstream having a relatively low H 2 /CO ratio of greater than 1 and equal to or less than 2.0. The syngas feedstream is preferably passed to a CO 2  removal zone, then to at least one Fischer-Tropsch zone, wherein the resulting Fischer-Tropsch product stream is passed to a separation zone to obtain a hydrocarbon-containing fraction that is hydroconverted to result in a distillate boiling range stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of Provisional Application 61/834,847filed Jun. 13, 2013.

FIELD OF THE INVENTION

This invention relates to a process for producing distillate fuels, suchas a diesel fuel, from a syngas feedstream having a relatively low H₂/COratio of greater than 1 and equal to or less than 2.0. The syngasfeedstream is preferably passed to a CO₂ removal zone, then to at leastone Fischer-Tropsch zone, wherein the resulting Fischer-Tropsch productstream is passed to a separation zone to obtain a hydrocarbon-containingfraction that is hydroconverted to result in a distillate boiling rangestream.

BACKGROUND OF THE INVENTION

There is a significant effort taking place in many parts of the world toproduce transportation fuels, particularly gasoline and distillatefuels, from renewable energy sources. For example, research anddevelopment in Fischer-Tropsch technology has been on-going for decadesto produce diesel fuels from syngas derived from natural gas and coal.More recently, there is a significant effort taking place to convertrenewable resources, such as biomass and triglycerides to transportationfuels. Before biomass can be converted to a transportation fuel via theFischer Tropsch or similar process (synthetic fuel, or synfuel), it mustfirst be converted to a syngas comprised primarily of H₂ and CO, whichcan then be sent to downstream processing to produce various chemicaland transportation fuel products. Conversion of biomass to syngas istypically accomplished by gasification that converts the biomass intopredominantly carbon monoxide and hydrogen (syngas) by reacting thecarbonaceous material of the biomass, at high temperatures, with acontrolled amount of oxygen and/or steam. The resulting syngas can be,inter alia, burned directly in internal combustion engines, used toproduce methanol and hydrogen, or methanol and dimethyl ether, orconverted via the Fischer-Tropsch process into synthetic transportationfuels.

Syngas produced from biomass has a different characteristic compositionthan syngas produced from coal or natural gas because of differences inthe heating value and chemical composition of biomass compared with coaland natural gas. Specifically, syngas produced from biomass has asignificantly lower H₂/CO ratio than syngas produced from natural gasbecause biomass has a lower heating value and is deficient in hydrogenrelative to that of natural gas. As such, processes developed to converthigh ratio (H₂/CO>2) syngas from natural gas are typically inefficientwhen applied to converting syngas derived from biomass. One way toovercome this problem is to “shift” the ratio of syngas produced frombiomass to a higher H₂/CO₂ ratio via the water-gas shift reaction. Thiscan result in higher H₂/CO ratio syngas, but can be thermallyinefficient because the reaction itself is exothermic and because of therequirement to produce steam, which results in lower thermal efficiencyand lower carbon yield to product. There are two well establishedprocesses for converting syngas to liquid transportation fuels. One isthe Fischer Tropsch process that is used to convert syngas to dieselfuel and typically utilizes syngas having an H₂/CO ratio greater than2:1. Another is the methanol to gasoline, or MTG process for producinggasoline from syngas via a methanol intermediate. Production of methanolalso requires a syngas having a H₂/CO ratio greater than 2. Therefore, aneed exists for a an improved process that can efficiently utilize lowH₂/CO ratio syngas produced from biomass, or other carbonaceousfeedstocks, having a relatively low heating value.

SUMMARY OF THE INVENTION

In accordance with the present invention there is provided a process forproducing a distillate boiling range transportation fuel stream from aninitial syngas feedstream, which syngas is comprised predominantly ofhydrogen and carbon monoxide, up to about 40 mol.% of other moietiesincluding water and carbon dioxide, substantially no sulfur, and has ahydrogen to carbon monoxide ratio of about 1 to about 2, which processcomprising:

a) conducting said syngas stream to a first Fischer Tropsch zone whereinit is reacted in the presence of a Fischer-Tropsch catalyst and underFisher-Tropsch conditions to result in a first Fischer-Tropsch productstream;

b) conducting said first Fischer-Tropsch product stream to a firstseparation zone resulting in a first aqueous-containing stream, a firstgaseous stream containing unreacted syngas, and a first Fischer-Tropschhydrocarbon-containing product stream comprised of both lighthydrocarbon fraction and a heavier hydrocarbon fraction;

c) conducting said first vapor stream containing unreacted syngas to asecond Fischer-Tropsch reaction zone wherein it is reacted in thepresence of a Fischer-Tropsch catalyst and under Fisher-Tropschconditions to result in a second Fischer-Tropsch product stream;

d) conducting said second Fischer-Tropsch product stream to a secondseparation zone resulting in a second aqueous-containing stream, asecond vapor stream containing unreacted syngas, and a secondFischer-Tropsch hydrocarbon product stream comprised of a lighthydrocarbon fraction and a heavier hydrocarbon fraction;

e) conducting said first and second Fischer-Tropsch hydrocarbon productstream to a hydroconversion zone wherein the streams are reacted in thepresence of hydrogen and a hydroconversion catalyst and underhydroconversion reaction conditions to result in a hydroconversiongaseous stream and a distillate boiling range stream;

f) collecting said distillate boiling range stream;

g) conducting said hydroconversion gaseous stream from step e) above andthe stream containing any remaining unreacted syngas from step d) aboveto a third separation zone resulting in an aqueous-containing stream, ahydrocarbon stream comprised of hydrocarbons having 5 or more carbonatoms, and a tail-gas stream;

h) collecting the hydrocarbon stream comprised of hydrocarbons having 5or more carbon atoms;

i) conducting said tail-gas stream to a reforming zone wherein it isreformed to a reformed syngas stream having a hydrogen to carbonmonoxide ratio equal to or greater than that of said initial syngasstream;

j) conducting at least part of said reformed syngas stream to saidsecond Fischer-Tropsch reaction zone; and

k) removing carbon dioxide from at least one gaseous stream in saidprocess in a carbon dioxide removal zone.

In a preferred embodiment, at least a portion of the reformed syngasstream is conducted to a carbon dioxide removal zone to prevent build-upof carbon dioxide in the system.

In another preferred embodiment a carbon dioxide-lean stream from asecond carbon dioxide removal zone downstream of said reforming zone isconducted to the syngas feed stream prior to it being introduced into afirst carbon dioxide removal zone.

In another preferred embodiment of the present invention at least aportion of the carbon dioxide-lean stream produced from the removal ofcarbon dioxide from the reformed tail-gas, or reformed syngas, stream isintroduced into the carbon-dioxide-lean stream being conducted from afirst carbon dioxide removal zone to said first Fischer-Tropsch zone.

In a preferred embodiment of the present invention the syngas is derivedfrom the gasification of a biomass.

BRIEF DESCRIPTION OF THE FIGURE

FIG. 1/1 hereof is a simplified process flow diagram of a preferredembodiment of the present invention for converting a syngas to adistillate fuels.

DETAILED DESCRIPTION OF THE INVENTION

The process of the present invention will produce transportation fuelsin the distillate boiling range, which will be from about 150° C. toabout 300° C. Non-limiting examples of such fuels include jet fuels,diesel fuels, kerosene, and blending components thereof. Syngas streamssuitable for use in the present invention are those having a hydrogen tocarbon monoxide ratio of greater than 1 but less than or equal to 2.0,preferably from about 1.2 to about 1.9, and more preferably from about1.5 to about 1.8. The syngas stream will also contain substantially nosulfur component, but can include up to about 40 mol %, preferably up toabout 20 mol %, more preferably up to about 10 mol %, even morepreferably up to about 7 mol %, and most preferably up to about 5 mol %of other moieties, comprised primarily of carbon dioxide, water,nitrogen, and argon. At least an effective amount of one or more gaseousstreams can be purged from the process to maintain these levels. Themajor portion of these other moieties, up to about 100%, will typicallybe carbon dioxide and the sum of hydrogen plus carbon monoxide willpreferably be greater than 80 mol %.

Syngas streams that can be used in the practice of the present inventioncan be derived from any source as long as they meet the above hydrogento carbon monoxide requirement. It is preferred that the syngas streambe derived from a renewable source, preferably from a biomass, and morepreferably from a lignocellulosic feedstock. The “lignocellulosicfeedstock,” can be any type of plant biomass such as, but not limitedto, non-woody plant biomass, cultivated crops, such as, but not limitedto, grasses, for example, but not limited to, C4 grasses, such asswitchgrass, cord grass, rye grass, miscanthus, reed canary grass, or acombination thereof, or sugar processing residues such as bagasse, orbeet pulp, agricultural residues, for example, soybean stover, cornstover, rice straw, rice hulls, barley straw, corn cobs, wheat straw,canola straw, rice straw, oat straw, oat hulls, corn fiber, recycledwood pulp fiber, sawdust, hardwood, for example aspen wood and sawdust,softwood, or a combination thereof. Further, the lignocellulosicfeedstock can include cellulosic waste material such as, but not limitedto, newsprint, cardboard, sawdust, and the like. For urban areas, thebest potential plant biomass feedstock includes yard waste (e.g., grassclippings, leaves, tree clippings, and brush) and vegetable processingwaste.

Lignocellulosic feedstocks can also include a single specie of fiber oralternatively, a mixture of species of fibers that originated fromdifferent lignocellulosic feedstocks. Furthermore, the lignocellulosicfeedstock can be comprised of fresh lignocellulosic feedstock, partiallydried lignocellulosic feedstock, fully dried lignocellulosic feedstock,or a combination thereof. In general, the term “biomass” as used hereinincludes all of the terms, plant biomass, liqnocellulosic, cellulosic,and hemicellulosic. It is preferred that the biomass used in thepractice of the present invention be comprised of at least about 30 wt.% cellulose, based on the total weight of the biomass.

It is also preferred that the biomass be converted to a syngas bygasification, more preferred by the gasification process disclosed inco-pending U.S. patent application Ser. No. 13/371,282 filed on Feb. 10,2012, which is incorporated herein, in its entirety, by reference. Thebiomass is preferably dried before feeding it to a gasifier. It ispreferred that the biomass, after drying, contain no more than about 20wt. %, preferably not more that about 15 wt. %, and more preferably nomore than about 10 wt. % water, based on the total weight of the biomassafter drying. The biomass is subjected to a size reduction step toreduce it to a size suitable for gasification, or for a feed to atorrefaction step. It is preferred that the size reduction step producea biomass having an average particle size of about 1 micron to about 3inches, preferably from about 150 microns to about 1.5 inches, and morepreferably from about 300 microns to 1.5 inches. The fibrous structureof the biomass makes it very difficult and costly to reduce its particlesize. Non-limiting examples of mechanical size reduction equipmentinclude rotary breakers, roll crushers, jet mills, cryogenic mills,hammermills, impactors, tumbling mills, roller mills, shear grinders,and knife mills. Hammermills are preferred for the practice of thepresent invention.

It is more preferred that the biomass be reduced in size aftertorrefying it at moderate temperatures in a substantially oxygen-freeatmosphere. Torrefaction increases the energy density of cellulosicmaterials by decomposing the fraction of hemicelluloses that isreactive. Thus, the energy content per unit mass of torrefied product isincreased. Much of the energy that is lost during torrefaction is in anoff-gas (tor-gas) that contains combustibles, which can be burned toprovide some of the heat required by the torrefaction process. Apreferred torrefaction process is taught in co-pending U.S. patentapplication Ser. No. 12/825,887 filed on Jun. 29, 2010 which is alsoincorporated herein, in its entirety, by reference.

Torrefaction of biomass of the present invention is conducted attemperatures from about 200° C. to about 350° C., preferably from about220° C. to about 320° C., more preferably from about 250° C. to about300° F. During torrefaction, the biomass properties are changed, whichresults in better fuel quality for combustion and gasificationapplications. Typically, torrefaction is followed by pelletizing toyield a product that is suitable as a fuel substitute for coal. In thiscase, the torrefied biomass of the present invention need not bepelletized, but is instead reduced to a particle size that will besuitable for use in a fluid-bed gasifier. In the torrefaction process ofthe present invention, the hemicelluloses and, depending on severity,some of the constituents in the biomass undergo hydrolysis anddehydration reactions. The process primarily removes CH₃O—, HCOO—,CH₃COO— functional groups from the hemicellulose and lignin. Hydrolysisreactions can also cleave the C—O—C linkages in the polymeric chainsthat comprise the major constituents in the biomass. The acidiccomponents in the tor-gas and the ash components in the biomass have thepotential to catalyze these reactions. The torrefaction process producesa tor-gas and a solid product having higher energy density than thefeedstock and a tor-gas. The solid product can result in char duringgasification and can contribute to heat balance needed for the gasifier.Particle size reduction can also occur during this process as a resultof chemical action rather than mechanical actions as in grinding.Overall, the process uses less electrical power to achieve a desireddegree of size reduction than mechanical size reduction withouttorrefaction.

The gasification process as applied to the conversion of carbonaceousmaterials involves many individual reactions associated with conversionof carbon, hydrogen, and oxygen into products involving steam, hydrogen,oxides of carbon, soot or tars and hydrocarbons. At elevatedtemperatures (>530° C.) associated with gasification, the major productsare typically steam and syngas comprised of hydrogen, CO₂, CO andmethane. Chars and soot represent compounds rich in carbon and maycontain small amounts (<5%) of hydrogen.

The present invention can be better understood with reference to theFIGURE hereof which is simplified process flow scheme for practicing apreferred embodiment of the present invention. This FIGURE shows two CO₂removal zones C1 and C2 as a more preferred mode of operation, but itwill be understood that only one CO₂ removal zone can be used eitherupstream of first Fischer-Tropsch reaction zone FT1 or anywhere else inthe process loop. For example, a CO₂ removal zone can be employeddownstream of third separation zone S1 or downstream of reforming zoneR. A preferred mode of operation is shown in this FIGURE wherein thereare two CO₂ separation zones, one to remove CO₂ from the syngasfeedstream upstream of first Fischer-Tropsch reaction zone FT1 and onedownstream of reforming zone R1. This FIGURES shows syngas feedstream SGis conducted via line 10 to a first CO₂ removal zone C1. The syngasfeedstream can optionally be combined with a portion of reformedtail-gas, line 49, to form stream 11.

Syngas leaving the gasifier will typically need to be cooled and cleanedbefore it is suitable as a feedstream for chemical synthesis. It willtypically contain various constituents that can foul downstreamequipment, damage compressors, and poison catalysts used in downstreamprocesses. Solids entrained in the syngas are typically fines that weregenerated during the attrition of solids circulating in a gasifier, ashgenerated from the biomass, and soot. Syngas derived from biomassgenerally contains relatively large amounts of CO₂ compared to syngasderived from natural gas and coal. This is a consequence of the lowheating value of biomass, as well as the process conditions needed toproduce a syngas having the desired H₂ to CO ratio for downstreamprocessing, such as for the production of higher value liquid products.The overall yield of desired liquid product from syngas can be increasedby removing a target amount of CO₂, sometimes removing as much CO₂ aspossible.

Any suitable CO₂ removal technology can be used in the practice of thepresent invention. Non-limiting examples of such technologies includeabsorption, adsorption, and the use of membrane technology. Non-limitingexamples of absorption technologies include chemical absorption, such asthe use of MEA or a caustic, and physical absorption such as Selexol andRectisol processes. In the Selexol process (now licensed by UOP LLC),the Selexol solvent dissolves (absorbs), acid gases from the feed gas atrelatively high pressure, usually about 300 to about 2000 psia (2.07 to13.8 MPa). The rich solvent containing the acid gases is then let downin pressure and/or steam stripped to release and recover the acid gases.The Selexol process is similar to the Rectisol process, which usesrefrigerated methanol as the solvent. The Selexol solvent is a mixtureof the dimethyl ethers of polyethylene glycol. Both the Selexol Processand the Rectisol process are well known to those having at leastordinary skill in the art so a detailed discussion of these processes isnot necessary for an understanding or enablement of the presentinvention. The Selexol Process is described in more detail in U.S. Pat.No. 4,581,154 which is incorporated herein, in its entirety, byreference.

Non-limiting examples of adsorption technologies include the use ofadsorber beds containing an adsorbent such as alumina or a zeolite.Non-limiting examples of membrane technology include gas separationusing an agent such as polyphenyleneoxide or polydimethylsiloxane, orgas adsorption using an agent such as polypropylene.

It is preferred to use multi-stage membrane technology for the removalof CO₂, such as that taught in U.S. Pat. No. 8,435,326 which isincorporated herein, in its entirety, by reference. Membranes suitablefor use in the practice of the present invention are those that arecapable of providing a separation factor of CO₂ to H₂ of at least about5 to 1, preferably at least about 7 to 1, and more preferably at leastabout 10 to 1. This separation factor is not based on the permeation ofpure gases, CO₂ and H₂, but on permeation of those gases from the syngasmixture. Measurements of permeation of pure gases through membranes areunreliable as predictors of separation factors that are obtained fromgaseous mixtures. Such membranes are preferred because they have agreater affinity for CO₂ to adsorb on certain nano-porous media, such aszeolites and silica. This greater affinity facilitates, and even boosts,permeation through such media, while hindering or blocking all othergaseous species. There are several advantages of using such membranes.First, such a membrane system is energy efficient. While reducing theCO₂ concentration at least about 5-fold, the retentate process streamwill retain about 65 to 70 vol. % H₂. Secondly, such a membrane willyield a relatively high concentration (>85%) CO₂ in the permeate. Third,such membranes allow for the adjustment of the desired retentate CO₂ andH₂/CO levels via adjustments by such things as feed flow, pressure andtemperature.

While membranes suitable for use in the practice of the presentinvention can be of both the so-call Type I and Type-II membranes, theType II membranes will be preferred and they are generally relativelythin supported nano- and micro-porous materials. Such micro-porousmembranes will preferably contain a connected network of about 0.6 nmpores in which small molecules can propagate by diffusion. Processconditions will be chosen such that the membrane becomes >50% saturatedwith CO₂ at the high pressure side. This leads to a very highselectivity for CO₂ relative to any other gas molecule, particularly H₂.Preferred membrane materials include amorphous silica for operation attemperatures less than about 400° C., micro-porous γ-alumina foroperations less than about 200° C., and pore-modified zeolite-Y foroperations less than about 100° C. A Type I membrane is defined as amembrane whose permeability for various compounds is only determined bythe relative diffusivities of those compounds in the pore structure ofthe membrane. A Type II membrane is defined as a membrane whosepermeability for various compounds is also impacted by the interactionof those compounds with specific active sites within the membrane.

In the case where the syngas steam is taken directly from a gasifier,the pressure of the syngas stream exiting the gasifier will be dependenton the particular gasifier employed. For example, some gasifiers are lowpressure gasifiers whereas others are medium to high pressure gasifiers.If the syngas stream is at too low a pressure it will be passed througha compression zone to increase its pressure to at least the operatingpressure of the membrane used in CO₂ separation zone C1. This pressurewill be from about 20 psig to about 1000 psig, preferably from about 50psig to about 700 psig, and most preferably from about 100 to about 400psig. The use of the CO₂ separation steps is to cost effectively removean effective amount of CO₂ from the syngas stream. It may be desirableto leave some CO₂ in the syngas stream to act as a diluent. The amountof CO₂ left in the syngas stream will be less than about 25 vol. %,preferably less than about 15 vol. %, and more preferably less thanabout 5 vol. %, based on the total volume of the syngas stream. A secondCO₂ removal zone can be used depending on the operating conditions ofreforming zone R, particularly if too much CO₂ starts to be accumulatedin the process. To prevent this, it preferred that a CO₂ removal zone beused downstream of reforming zone R, although it can also be locatedanywhere else in the process loop to treat a CO₂-containing gaseousstream.

A CO₂-rich stream is rejected via line 60. The resulting CO₂-lean syngasstream 12 can optionally be combined with a portion of reformed tail gas50 to form stream 13. The combination of syngas and reformed tail gasstreams 10, 49, and 50 form stream 13 which will preferably have ahydrogen to carbon monoxide ratio greater than about 1.6 but less thanor equal to 2.2, preferably greater than 1.6 but less than 2.0, morepreferably from 1.7 to 1.9, and most preferably from 1.8 to 1.9. Stream13 is then conducted to first Fischer-Tropsch reactor FT1 where it isconverted under conventional Fischer-Tropsch conditions and in thepresence of a Fischer-Tropsch catalyst to produce a hydrocarbon liquidproduct steam 14 that is primarily comprised of paraffinic materials,which are ideal for the production of diesel fuels.

Fischer-Tropsch process conditions include temperatures from about 150°C. to about 300° C. Fischer-Tropsch catalysts are well known in the artand typically contain a Group 7 to Group 10, preferably a Group 8transition metal on a metal oxide support. Groups of elements referredto in this document are those from the so-called common, or standardTable of the Elements containing Groups 1 to 18. The catalysts may alsocontain a noble metal promoter(s) and/or crystalline molecular sieves.Non-limiting examples of metals of Groups 7 to 10 are those selectedfrom the group consisting of Fe, Ni, Co, Ru and Re, with cobalt beingpreferred. A preferred Fischer-Tropsch catalyst comprises effectiveamounts of cobalt and one or more of a metal selected from the groupconsisting of Re, Ru, Pt, Fe, Ni, Th, Zr, Hf, U, Mg and La on a suitableinorganic support material, preferably one which comprises one or morerefractory metal oxides. In general, the amount of cobalt present in thecatalyst is between about 1 to about 50 wt. % based on the total weightof the catalyst composition. The catalysts can also contain basic oxidepromoters such as ThO₂, La₂O₃, MgO, TiO₂, and ZrO₂, noble metals (Pt,Pd, Ru, Rh, Os, Ir), coinage metals (Cu, Ag, Au), and other transitionmetals such as Fe, Mn, Ni, and Re. Non-limiting examples of supportmaterials suitable for use herein include alumina, silica, magnesia andtitania and mixtures thereof. Useful catalysts and their preparation areknown and disclosed in U.S. Pat. No. 4,568,663, which is incorporatedherein, in its entirety, by reference and which is intended to beillustrative but non-limiting relative to catalyst selection.

Product stream 14 from first Fischer-Tropsch reactor FT1 will becomprised of a gaseous component and a hydrocarbon liquid componenthaving carbon numbers up to about 100 or more. Fisher-Tropsch liquidsare typically comprised of predominantly straight chain paraffins havingabout 5 to about 10 wt. % olefins and less than about 1 wt. %oxygenates, based on the total weight of the Fischer-Tropsch liquids.This gaseous component will typically be comprised of methane, CO₂,water, unreacted syngas, and C₂ to C₇ hydrocarbons. The unreacted syngasin the gaseous stream will have a lower H₂/CO ratio than the syngas fedto the Fischer-Tropsch reactor because the Fischer-Tropsch reactionconsumes H₂ at a molar ratio of 2 to about 2.2 times that of COconsumption. By convention, we will refer to this lower ratio ofunreacted syngas as “partially reacted syngas” to reflect theunderstanding that this syngas will have a lower H₂/CO ratio than thesyngas fed to the reactor. Product stream 14 is sent to first separationzone S1 where one fraction 16 will be comprised of water that will alsotypically contain small amounts of alcohols. Another fraction 20 will becomprised of partially reacted syngas, while a third fraction 18, willbe comprised of both a light hydrocarbon fraction and a heavyhydrocarbon fraction. The light hydrocarbon fraction will typically becomprised predominantly of hydrocarbons in the carbon range of about C5to about C20. Less than about 5 wt. % of the C5 to C20 fraction willhave hydrocarbons in the range of C20+. The heavy hydrocarbon fractionwill typically be comprised of hydrocarbons predominantly in the carbonrange of about C8 to C20+. This mixed hydrocarbon product stream fromFischer-Tropsch reaction zone FT1 is sent to a hydroconversion zone HCvia line 18. It will be understood that the term “hydrocarbon” as usedherein means molecules comprised of only carbon and hydrogen as well asmolecules comprised of carbon, hydrogen, and a small amount of one ormore heteroatoms, preferably those selected from oxygen and nitrogen.

Stream 20 may be combined with a portion of reformed tail gas 51, fromsecond CO₂ separation zone C2 to form stream 21 before being conductedto second Fischer-Tropsch reactor FT2, the product of which is sent tosecond separation zone S2. The process conditions of FT2 and S2 aresubstantially the same as the conditions of FT1 and S1, and the inputand output streams have substantially the same compositions andproperties. The combined input stream 21 to FT2 will preferably have ahydrogen to carbon monoxide ratio substantially the same to stream 13which is introduced into first Fischer-Tropsch zone FT1. This isaccomplished by concurrently operating first Fischer-Tropsch reactionzone FT1, and tail-gas reforming zone R, under conditions such thatpartially reacted syngas stream 20 and the reformed and CO₂-leantail-gas stream 51 will have substantially the same H₂/CO ratio assyngas feedstream 13, when mixed together. The hydrocarbon productstream 26, from second separation zone S2, is conducted tohydroconversion zone HC. The remaining unreacted syngas and lighthydrocarbon gases are conducted via line 36 to third separation zone S3.

Light hydrocracking and predominantly hydroisomerization will preferablytake place in hydroconversion zone HC. Any suitable predominantlyhydroisomerization catalyst can be used for hydroconversoin zone HC. Onenon-limiting type of catalyst that can be used is a conventionalhydrotreating catalysts comprised of at least one Group 6 metal and atleast one Groups 8 to 10 metal. Preferred metals include Ni, W, Mo, Coand mixtures thereof. These metals, or mixtures of metals, are typicallypresent as oxides or sulfides on refractory metal oxide supports. Themixture of metals may also be present as bulk metal catalysts whereinthe amount of metal is about 30 wt. % or greater, based on the totalweight of the catalyst. It is within the scope of this invention thatthe active metal for the hydrotreating catalyst be one or more noblemetals selected from Pt and Pd with or without a Group 6 metal. The morepreferred catalysts for use in the present invention are fluorided Group8 metal-on-alumina containing catalyst compositions. The preferred Group8 metal is platinum and the most preferred alumina containing support isselected from the group consisting of alumina and silica-alumina. It isto be understood that the alumina-containing component may contain minoramounts of other materials, such as, for example, silica, and thealumina herein encompasses alumina-containing materials.

A preferred fluoride Group 8 metal-on-alumina catalyst comprises about0.1 to about 2 percent, preferably from about 0.3 to about 0.6 percentGroup 8 metal and from about 2 percent to about 10 percent fluoride,preferably from about 5 percent to about 8 percent fluoride, based onthe total weight of the catalyst composition (dry basis), said fluorideconcentration being referred to herein as the bulk fluorideconcentration.

A more preferred catalyst of the present invention will have a fluorideconcentration less than about 3.0 weight percent, preferably less thanabout 1.0 weight percent and most preferably less than 0.5 weightpercent at its outer surface layer, provided the surface fluorideconcentration is less than the bulk fluoride concentration. The outersurface is measured to a depth less than one one hundredth of an inch.The surface fluoride was calculated from the total fluoride analysis andthe electron microscope analysis. The remaining fluoride is distributedwith the Group 8 metal at a depth below the outer shell into and withinthe particle interior. Catalysts of the preferred type are described indetail in U.S. Pat. Nos. 4,919,786 and 4,923,841 both of which areincorporated herein in their entirety.

While alumina-containing support materials are preferred, other suitablemetal oxide supports include silica and titania. Preferred aluminas areporous aluminas such as gamma or eta alumina. The acidity of metal oxidesupports can be controlled by adding promoters and/or dopants, or bycontrolling the nature of the metal oxide support, e.g., by controllingthe amount of silica incorporated into a silica-alumina support.Non-limiting examples of promoters and/or dopants suitable for useherein include halogen (especially fluorine), phosphorus, boron, yttria,rare-earth oxides and magnesia. Promoters, such as halogens, generallyincrease the acidity of metal oxide supports while mildly basic dopants,such as yttria and magnesia, tend to decrease the acidity of suchsupports. Fluorine is the most preferred promoter.

Effective hydroconversion conditions that can be used in the practice ofthe present invention include temperatures from about 250° C. to about400° C., preferably about 270° C. to about 350° C., pressures of fromabout 791 to about 20786 kPa (about 100 to about 3000 psig), preferablyabout 15 kg/cm to about 175 kg/cm² (about 200 to about 2500 psig),liquid hourly space velocities of from about 0.1 to about 10 hr⁻¹,preferably about 0.1 to about 5 hr⁻¹ and hydrogen treat gas rates fromabout 45 to about 1780 m³/m³ (about 250 to about 10000 scf/B),preferably about 89 to about 890 m³/m³ (about 500 to about 5000 scf/B.

The hydroconversion step can be performed in one or more fixed bedreactors, or reaction zones within a single reactor, each of which cancomprise one or more catalyst beds of the same, or different, catalyst.Although other types of catalyst beds can be used, fixed beds arepreferred. Such other types of catalyst beds suitable for use hereininclude fluidized beds, ebullating beds, slurry beds, and moving beds.Interstage cooling or heating between reactors or reaction zones, orbetween catalyst beds in the same reactor or reaction zone, can beemployed since the reaction is generally exothermic. A portion of theheat generated during hydrotreating can be recovered. Where this heatrecovery option is not available, conventional cooling may be performedthrough cooling utilities, such as cooling water or air, or through useof a hydrogen quench stream. In this manner, optimum reactiontemperatures can be more easily maintained.

Hydroconversion zone HC requires a hydrogen input stream 28. Thereaction product from hydroconversion zone HC is fractionated to producea gaseous stream 32, which is comprised predominantly of lighthydrocarbons with the remainder comprised of permanent gases and adistillate boiling range stream 30.

Gaseous streams, lines 32 and 36, are conducted to a third separationzone S3. The exiting tail gas stream 42 from separation zone S3 issubstantially free of water and hydrocarbons having 5 or more carbonatoms, and is predominantly comprised of CO₂, methane and other lighthydrocarbon gases, as well as unreacted syngas, with smaller amounts ofaccumulated atmospheric gases from recycle such as N₂ and argon. Wateris removed via line 38 and hydrocarbons having 5 or more carbon atomsare collected via line 40 as a naphtha blend stream. The naphtha blendstream composition can be varied to achieve a predetermined boilingpoint range, but will preferably be comprised predominantly ofhydrocarbons in the carbon range of about C5 to about C10.

The resulting tail-gas stream is conducted via line 42 to reforming zoneR, where it is reformed to a syngas having a hydrogen to carbon monoxideratio equal to or greater than that of stream 10 and greater than thatof stream 20. Any reforming technology known to one skilled in the artcan be used in R, including but not limited to stream reforming,autothermal reforming, as well as partial oxidation. Depending on theinput requirements of the chosen reforming process, steam, oxygen,and/or a fuel can be introduced into R via lines 43 and 45.

The process of the present invention will preferably include one or morelocations where a fraction of the gaseous stream can be purged in orderto prevent accumulation of inert gases such as nitrogen and argon. Theoptimal location(s) of these one or more purge stream(s) will depend onthe specific equipment configuration and can be readily determined byone skilled in the art. Two more preferred embodiments of this purgestep are shown in the FIGURE hereof, as a side product from R (stream44) and as a direct purge from the reformed tail gas stream (stream 47).One skilled in the art will also recognize that the purge stream(s) maycontain components that could be either utilized directly or could berecovered using known separation techniques for either use within thisprocess or export.

The process of the present invention will also have one or more gascompression steps (not shown) to offset the pressure drop across processequipment. The optimal location(s) of these one or more compressionsteps will depend on the specific equipment configuration and can bereadily determined by one skilled in the art.

The syngas product stream (reformer syngas) from reforming zone R isconducted via lines 46 and 48 to second CO₂ removal zone C2, which is anoptional CO₂-removal zone depending on how the reformer is run. Forexample, the reformer can be run to achieve a high ratio of H₂ to CO.That is, at ratios higher than the ratio of H₂ to CO in the syngasfeedstream 10, or higher than the ratio of H₂ to CO in stream 13 tofirst Fischer-Tropsch zone FT1. CO₂ is rejected via line 62. Theresulting CO₂-lean reformed tail gas stream 52 is conducted back to mixwith the feeds to one or both of the Fisher-Tropsch reaction zones FT1and FT2. It will be understood that the resulting CO₂-lean tail gasstream 52, depending on the level of CO₂, can be split into three equalor unequal fractions 49, 50 and 51. It will also be understood thatfirst CO₂ removal zone can be eliminated and CO₂ removed from theprocess after the reformer in second CO₂ removal zone C2.

What is claimed is:
 1. A process for producing a distillate boilingrange transportation fuel stream from an initial syngas feedstream,which syngas is comprised predominantly of hydrogen and carbon monoxide,up to about 40 mol.% of other moieties including water and carbondioxide, substantially no sulfur, and has a hydrogen to carbon monoxideratio of about 1 to about 2, which process comprising: a) conductingsaid syngas stream to a first Fischer Tropsch zone wherein it is reactedin the presence of a Fischer-Tropsch catalyst and under Fisher-Tropschconditions to result in a first Fischer-Tropsch product stream; b)conducting said first Fischer-Tropsch product stream to a firstseparation zone resulting in a first aqueous-containing stream, a firstgaseous stream containing unreacted syngas, and a first Fischer-Tropschhydrocarbon-containing product stream comprised of a light hydrocarbonfraction and a heavier hydrocarbon fraction; c) conducting said firstvapor stream containing unreacted syngas to a second Fischer-Tropschreaction zone wherein it is reacted in the presence of a Fischer-Tropschcatalyst and under Fisher-Tropsch conditions to result in a secondFischer-Tropsch product stream; d) conducting said secondFischer-Tropsch product stream to a second separation zone resulting ina second aqueous-containing stream, a second gaseous stream containingunreacted syngas, and a second Fischer-Tropsch hydrocarbon-containingproduct stream comprised of a light hydrocarbon fraction and a heavierhydrocarbon fraction; e) conducting said first and secondFischer-Tropsch hydrocarbon product stream to a hydroconversion zonewherein the streams are reacted in the presence of hydrogen and ahydroconversion catalyst and under hydroconversion reaction conditionsto result in a hydroconversion gaseous stream and a distillate boilingrange stream; f) collecting said distillate boiling range stream; g)conducting the gaseous stream from step e) above and the streamcontaining any remaining unreacted syngas from step d) above to a thirdseparation zone resulting in an aqueous-containing stream, ahydrocarbon-containing stream comprised of hydrocarbons having 5 or morecarbon atoms, and a tail-gas stream; h) collecting thehydrocarbon-containing stream comprised of hydrocarbons having 5 or morecarbon atoms; i) conducting said tail-gas stream to a reforming zonewherein it is reformed to a reformer syngas stream having a hydrogen tocarbon monoxide ratio equal to or greater than that of said initialsyngas stream; j) conducting at least part of said reformed syngasstream to said second Fischer-Tropsch reaction zone; and k) removingcarbon dioxide from at least one gaseous stream in said process in acarbon dioxide removal zone.
 2. The process of claim 1 wherein the ratioof hydrogen to carbon monoxide of the syngas feedstream is from about1.2 to about 1.9.
 3. The process of claim 2 wherein the ratio ofhydrogen to carbon monoxide of the syngas feedstream is from about 1.6to about 1.9.
 4. The process of claim 1 wherein a part of the reformedsyngas stream is conducted to the first Fischer-Tropsch reaction zone.5. The process of claim 1 wherein a carbon dioxide removal zone islocated upstream of said first Fischer-Tropsch reaction zone therebyremoving carbon dioxide from said syngas feedstream.
 6. The process ofclaim 4 wherein at least a fraction of said reformer syngas stream isconducted to said carbon dioxide removal zone.
 7. The process of claim 1wherein a second carbon dioxide removal zone is located downstream ofsaid reforming zone and wherein at least a fraction of the resultingcarbon dioxide lean stream is conducted to said Fischer-Tropsch reactionzone.
 8. The process of claim 1 wherein an effective amount of a gaseousstream from any process unit of the process is purged from the processto prevent accumulation of contaminants.
 9. The process of claim 8wherein an effective amount of gaseous stream is purged downstream ofsaid reforming zone.
 10. The process of claim 8 wherein an effectiveamount of gaseous stream is purged downstream of at least one of saidseparation zones.
 11. The process of claim 1 wherein the syngas isobtained from a biomass.
 12. The process of claim 1 wherein the syngasis received via the gasification of a biomass.
 13. The process of claim11 wherein the biomass is selected from the group consisting ofnon-woody plant biomass, cultivated crops, grasses, sugar processingresidues, agricultural residues, and a combination thereof.
 14. Aprocess for producing a distillate boiling range transportation fuelstream from an initial syngas feedstream obtained from the gasificationof a biomass, which syngas is comprised predominantly of hydrogen andcarbon monoxide, up to about 40 mol.% of other moieties including waterand carbon dioxide, substantially no sulfur, and has a hydrogen tocarbon monoxide ratio of about 1.2 to about 1.9, which processcomprising: a) conducting said syngas stream to a first Fischer Tropschzone wherein it is reacted in the presence of a Fischer-Tropsch catalystand under Fisher-Tropsch conditions to result in a first Fischer-Tropschproduct stream; b) conducting said first Fischer-Tropsch product streamto a first separation zone resulting in a first aqueous-containingstream, a first gaseous stream containing unreacted syngas, and a firstFischer-Tropsch hydrocarbon-containing product stream comprised of alight hydrocarbon fraction and a heavier hydrocarbon fraction; c)conducting said first vapor stream containing unreacted syngas to asecond Fischer-Tropsch reaction zone wherein it is reacted in thepresence of a Fischer-Tropsch catalyst and under Fisher-Tropschconditions to result in a second Fischer-Tropsch product stream; d)conducting said second Fischer-Tropsch product stream to a secondseparation zone resulting in a second aqueous-containing stream, asecond gaseous stream containing unreacted syngas, and a secondFischer-Tropsch hydrocarbon-containing product stream comprised of alight hydrocarbon fraction and a heavier hydrocarbon fraction; e)conducting said first and second Fischer-Tropsch hydrocarbon productstream to a hydroconversion zone wherein the streams are reacted in thepresence of hydrogen and a hydroconversion catalyst and underhydroconversion reaction conditions to result in a hydroconversiongaseous stream and a distillate boiling range stream; f) collecting saiddistillate boiling range stream; g) conducting the gaseous stream fromstep e) above and the stream containing any remaining unreacted syngasfrom step d) above to a third separation zone resulting in anaqueous-containing stream, a hydrocarbon-containing stream comprised ofhydrocarbons having 5 or more carbon atoms, and a tail-gas stream; h)collecting the hydrocarbon-containing stream comprised of hydrocarbonshaving 5 or more carbon atoms; i) conducting said tail-gas stream to areforming zone wherein it is reformed to a reformed syngas stream havinga hydrogen to carbon monoxide ratio equal to or greater than that ofsaid initial syngas stream; j) conducting at least part of said reformedsyngas stream to said second Fischer-Tropsch reaction zone; and k)removing carbon dioxide from at least one gaseous stream in said processin a carbon dioxide removal zone.
 15. The process of claim 14 whereinthe ratio of hydrogen to carbon monoxide of the syngas feedstream isfrom about 1.6 to about 1.9.
 16. The process of claim 14 wherein a partof the reformed syngas stream is conducted to the first Fischer-Tropschreaction zone.
 17. The process of claim 14 wherein a carbon dioxideremoval zone is located upstream of said first Fischer-Tropsch reactionzone thereby removing carbon dioxide from said syngas feedstream. 18.The process of claim 4 wherein at least a fraction of said reformedsyngas stream is conducted to said carbon dioxide removal zone.
 19. Theprocess of claim 14 wherein a second carbon dioxide removal zone islocated downstream of said reforming zone and wherein at least afraction of the resulting carbon dioxide lean stream is conducted tosaid Fischer-Tropsch reaction zone.
 20. The process of claim 14 whereinan effective amount of a gaseous stream from any process unit of theprocess is purged from the process to prevent accumulation ofcontaminants.
 21. The process of claim 20 wherein an effective amount ofgaseous stream is purged downstream of said reforming zone.
 22. Theprocess of claim 20 wherein an effective amount of gaseous stream ispurged downstream of at least one of said separation zones.
 23. Theprocess of claim 14 wherein the syngas is obtained from a biomass. 24.The process of claim 14 wherein the syngas is received via thegasification of a biomass.
 25. The process of claim 23 wherein thebiomass is selected from the group consisting of non-woody plantbiomass, cultivated crops, grasses, sugar processing residues,agricultural residues, and a combination thereof.